U.S. patent application number 11/691071 was filed with the patent office on 2008-10-02 for wireless logging of fluid filled boreholes.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Francois Auzerais, Richard Timothy Coates, Dominique Guillot, Tarek M. Habashy, Douglas E. Miller, Rod Shampine, Philip Sullivan.
Application Number | 20080239872 11/691071 |
Document ID | / |
Family ID | 39789266 |
Filed Date | 2008-10-02 |
United States Patent
Application |
20080239872 |
Kind Code |
A1 |
Miller; Douglas E. ; et
al. |
October 2, 2008 |
Wireless Logging of Fluid Filled Boreholes
Abstract
A predetermined condition in a fluid-filled wellbore system can
be detected by generating at least one sound in the wellbore system
in response to the condition, such that a detectable change is
created in some characteristic of the emitted sound, and detecting
the at least one sound and the change, the detection being
indicative that the predetermined condition has occurred. Equipment
for facilitating detection of the condition can include a trigger
operable in response to the condition; a generator operable to emit
sound in the borehole and to create a detectable change in some
characteristic of the emitted sound in response to the trigger; and
at least one sensor operable to monitor the sound and detect the
change, the detection being indicative that the predetermined
condition has occurred. It is also possible to estimate a value of
a property of a fluid-filled wellbore system. This can be
accomplished by recording data including at least one of pressure
and rate of flow at one or more locations in the wellbore system,
and then estimating the value of the property by employing a model
for predicting at least one of pressure and rate of flow dependent
upon parameters detailing at least one of wellbore system geometry,
viscoacoustic properties of the fluid and entrained solids
contained in the wellbore system, locations of boundaries and
entrained solids, and characteristics and locations of disturbances
to pressure and flow in the wellbore system, in order to determine
a best prediction of some attribute of the recorded data.
Inventors: |
Miller; Douglas E.; (Sandy
Hook, CT) ; Sullivan; Philip; (Bellaire, TX) ;
Coates; Richard Timothy; (Middlebury, CT) ; Auzerais;
Francois; (Houston, TX) ; Habashy; Tarek M.;
(Burlington, MA) ; Guillot; Dominique;
(Somerville, MA) ; Shampine; Rod; (Houston,
TX) |
Correspondence
Address: |
SCHLUMBERGER-DOLL RESEARCH;ATTN: INTELLECTUAL PROPERTY LAW DEPARTMENT
P.O. BOX 425045
CAMBRIDGE
MA
02142
US
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Cambridge
MA
|
Family ID: |
39789266 |
Appl. No.: |
11/691071 |
Filed: |
March 26, 2007 |
Current U.S.
Class: |
367/83 ;
703/5 |
Current CPC
Class: |
G01V 1/52 20130101; E21B
47/005 20200501; E21B 47/18 20130101; E21B 47/06 20130101; E21B
47/095 20200501; G01V 1/48 20130101; E21B 47/047 20200501; E21B
47/07 20200501 |
Class at
Publication: |
367/83 ;
703/5 |
International
Class: |
G01L 11/04 20060101
G01L011/04 |
Claims
1. A method for estimating a value of a property of a liquid-filled
wellbore system, comprising the steps of: recording data including
at least one of pressure and rate of flow at one or more locations
in the wellbore system; and estimating the value of the property by
predicting at least one of pressure and rate of flow dependent upon
parameters detailing at least one of wellbore system geometry,
viscoelastic properties of the wellbore system, viscoacoustic
properties of the fluid and entrained solids contained in the
wellbore system, locations of boundaries and entrained solids, and
characteristics and locations of disturbances to pressure and flow
in the wellbore system, in order to determine a prediction of some
attribute of the recorded data.
2. The method of claim 1 wherein the property includes at least one
of pressure, pH, temperature, background radiation, location, fluid
viscosity, density, velocity, electrical resistance or
conductivity, compressive strength, shear strength attenuation and
acoustic transmistivity.
3. The method of claim 1 wherein the parameters include a general
representation of wellbore systems.
4. The method of claim 1 wherein the parameters include a
representation specific to the wellbore system from which the value
of the property is being estimated.
5. The method of claim 1 wherein the attribute of the recorded data
includes at least one of amplitude, frequency, attenuation,
dispersion, differential travel time and absolute travel time.
6. The method of claim 1 in which the attribute of the recorded
data includes the delay time of one or more peaks in the
cross-correlation of the response from a sensor detecting at least
one direct and at least one reflected disturbance.
7. The method of claim 1 including the further step of employing at
least one sensor in a supply portion of the system and at least one
sensor in a return portion of the system.
8. The method of claim 7 in which the attribute of the recorded
data is the delay time of one or more peaks in the
cross-correlation of the response from a sensor in the supply
portion of the system with the response from a sensor in the return
portion of the system.
9. The method of claim 1 including the further step of creating the
disturbances at known times.
10. The method of claim 1 including the further step of creating
the disturbances at known locations.
11. The method of claim 10 including the further step of creating
the disturbances at known times.
12. The method of claim 10 including the further step of triggering
creation of the disturbances by arrival of an entrained solid at a
known location.
13. The method of claim 12 wherein the location is a casing float
collar.
14. The method of claim 13 wherein the disturbances are due to
rupture of an entrained solid or membrane.
15. The method of claim 14 wherein the entrained solid is a wiper
plug.
16. The method of claim 12 including the further step of detecting
arrival with a mechanical, fluidic or electronic sensor deployed as
part of the wellbore system.
17. The method of claim 1 including the further step of creating
disturbances by changing pressure or flow.
18. The method of claim 1 including the further step of creating
disturbances by changing state of one or more valves diverting flow
from an input line.
19. The method of claim 1 including the further step of creating
disturbances by changing state of one or more valves diverting flow
into an output line.
20. The method of claim 1 including the further step of changing
the viscoelastic properties of the wellbore system by changing
state of one or more valves.
21. The method of claim 1 wherein the disturbances are at a
frequency in the range from DC to 40 kHz.
22. The method of claim 1 including the further step of recording
pressure at a frequency between 0 Hz and 1 kHz.
23. A method for detecting a predetermined condition in a
liquid-filled wellbore system, comprising the steps of: generating
at least one pressure pulse triggered in response to the condition;
and detecting the at least one generated pulse, the detection being
indicative that the predetermined condition has occurred.
24. The method of claim 23 wherein the predetermined condition
includes at least one of a specific level of pressure, pH,
temperature, background radiation, location, velocity, state of
cure of entrained cement, epoxy or other substance which gells and
sets over time after placement downhole, period of time, and any
combinations thereof.
25. The method of claim 23 including the further step of creating
the pressure pulse at a known location.
26. The method of claim 23 including the further step of creating a
low frequency or DC variation in pressure at a known location.
27. The method of claim 25 wherein the known location is a casing
float collar.
28. The method of claim 25 wherein the pressure pulse is caused by
rupture of an entrained solid or membrane.
29. The method of claim 23 wherein the pressure pulse is caused by
forcing a solid entrained object through a sequence of one or more
orificia.
30. The method of claim 28 wherein the entrained solid includes a
wiper plug.
31. Apparatus operable to estimate a value of a property of a
liquid-filled wellbore system, comprising: at least one sensor
operable to record data including at least one of pressure and rate
of flow at one or more locations in the wellbore system; and a
model for predicting at least one of pressure and rate of flow
dependent upon parameters detailing at least one of wellbore system
geometry, viscoelastic properties of the wellbore system,
viscoacoustic properties of the fluid and entrained solids
contained in the wellbore system, locations of boundaries and
entrained solids, and characteristics and locations of disturbances
to pressure and flow in the wellbore system, in order to determine
a best prediction of some attribute of the recorded data; and an
analyzer operable to estimate the value of the property from the
model.
32. The apparatus of claim 31 wherein the property includes at
least one of pressure, pH, temperature, background radiation,
location, fluid viscosity, density, velocity, electrical resistance
or conductivity, compressive strength, shear strength and acoustic
transmitivity.
33. The apparatus of claim 31 wherein the parameters include a
general representation of wellbore systems.
34. The apparatus of claim 31 wherein the parameters include a
representation specific to the wellbore system from which the value
of the property is being estimated.
35. The apparatus of claim 31 wherein the attribute of the recorded
data includes at least one of amplitude, frequency, attenuation,
dispersion and travel time.
36. The apparatus of claim 31 in which the attribute of the
recorded data includes the delay time of one or more peaks in the
cross-correlation of the response from a sensor detecting at least
one direct and at least one reflected disturbance.
37. The apparatus of claim 31 including at least one sensor in a
supply portion of the system and at least one sensor in a return
portion of the system.
38. The apparatus of claim 37 in which the attribute of the
recorded data is the delay time of one or more peaks in the
cross-correlation of the response from a sensor in the supply
portion of the system with the response from a sensor in the return
portion of the system.
39. The apparatus of claim 31 further including a mechanism
operable to create the disturbances at known times.
40. The apparatus of claim 31 further including a mechanism
operable to create the disturbances at known locations.
41. The apparatus of claim 40 wherein the mechanism is further
operable to create the disturbances at known times.
42. The apparatus of claim 40 wherein the mechanism is further
operable to trigger creation of the disturbances in response to
arrival of an entrained solid at a known location.
43. The apparatus of claim 42 wherein the location is a casing
float collar.
44. The apparatus of claim 43 wherein the disturbances are
generated by rupture of an entrained solid or membrane.
45. The apparatus of claim 44 wherein the entrained solid is a
wiper plug.
46. The apparatus of claim 42 further including a mechanical,
fluidic or electronic sensor deployed as part of the wellbore
system to detect arrival of the entrained solid.
47. The apparatus of claim 31 further including a modulator
operable to create the disturbances by changing pumping pressure or
flow.
48. The apparatus of claim 31 further including a modulator
operable to create the disturbances by changing state of one or
more valves diverting flow from an input line.
49. The apparatus of claim 31 further including a modulator
operable to create the disturbances by changing state of one or
more valves diverting flow into an output line.
50. The apparatus of claim 31 further including a modulator
operable to change the viscoelastic properties of the wellbore
system by changing state of one or more valves.
51. The apparatus of claim 31 wherein the disturbances are at a
frequency in the range from DC to 40 kHz.
52. The apparatus of claim 31 wherein the model includes parameters
for pressure at a frequency between 0.01 Hz and 1 kHz.
53. Apparatus operable to detect a predetermined condition in a
liquid-filled wellbore system, comprising: a trigger operable in
response to the condition; a pulse generator operable to generate
at least one pressure pulse in response to the trigger; and at
least one sensor operable to detect the at least one generated
pulse, the detection being indicative that the predetermined
condition has occurred.
54. The apparatus of claim 53 wherein the predetermined condition
includes at least one of a specific level of pressure, pH,
temperature, background radiation, location, velocity, state of
cure of entrained cement, epoxy or other substance which gells and
sets over time after placement downhole, period of time, and any
combinations thereof.
55. The apparatus of claim 53 wherein the pulse generator is
disposed at a known location.
56. The method of claim 53 wherein the pulse generator creates a
low frequency or DC variation in pressure at a known location.
57. The apparatus of claim 55 wherein the known location is a
casing float collar.
58. The apparatus of claim 55 wherein the pulse generator includes
an entrained solid or membrane, rupture of which creates the
pressure pulse.
59. The apparatus of claim 53 wherein the pressure pulse is caused
by forcing a solid entrained object through a sequence of one or
more orificia.
60. The apparatus of claim 58 wherein the entrained solid includes
a wiper plug.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This patent application is also related to the following
commonly-assigned U.S. Patent Application which is hereby
incorporated by reference in its entirety: Application Ser. No.
______, entitled "Determination of Downhole Pressure While
Pumping", filed on this same date (Attorney Docket No. 60.1702 US
NP).
FIELD OF THE INVENTION
[0002] This invention is generally related to oil and gas wells,
and more particularly to wireless logging of fluid filled
boreholes.
BACKGROUND OF THE INVENTION
[0003] Achieving accurate, real-time measurements during well
completion and stimulation treatments has long been a goal in the
oil and gas industry. Accurate measurement of bottom hole pressure
during fracture treatments, for example, would allow an operator to
observe fracture growth trends in real-time, and change treatment
conditions accordingly. Similarly, measurement of ball location
would facilitate acid bailout treatments. However, real-time
measurements of borehole completion and stimulation treatments are
rarely performed with current technology because the borehole
environment is hostile to wiring and tends to rapidly attenuate
electromagnetic signals. For example, the abrasiveness of the
fracturing slurry is destructive to any exposed cable placed in the
wellbore for delivering data to the surface.
[0004] Techniques for providing real-time measurements during
drilling operations are known. For example, formation properties
may be measured during the excavation of the borehole, or shortly
thereafter, through the use of tools integrated into the bottomhole
assembly ("BHA"). Logging while drilling has the advantage of
measuring properties of a formation before drilling fluids invade
deeply. However, many wellbores prove to be difficult or even
impossible to measure with conventional wireline tools, especially
highly deviated wells. Consequently, when drilling operations have
ended and the BHA is withdrawn from the borehole, e.g., in the
completion phase or during stimulation treatments, it is often
impractical to obtain real-time measurements.
[0005] One attempt to deliver bottom hole pressure measurement data
in real-time is described in Doublet, L. E., Nevans, J. W., Fisher,
M. K., Heine, R. L, Blasingame, T. A., Pressure Transient Data
Acquisition and Analysis Using Real Time Electromagnetic Telemetry,
SPE 35161, March 1996 ("Doublet"). Doublet teaches that pressure
measurements are transmitted from a downhole gauge to the surface
through the formation strata via electromagnetic signals. Although
this technique has been used successfully on some wells, it is
limited by the well depth and the types of rock layers through
which a signal could be transmitted clearly. In particular,
electromagnetic signals are rapidly attenuated by the formation.
These limitations render the technique impractical for use in many
wells, and particularly in deep wells.
[0006] Gathering data from the region of a formation between
boreholes is also known. Typically, a seismic source in one
borehole creates waves which are detected in another borehole.
Formation properties may be calculated from attenuation, dispersion
and travel time of the waves between the boreholes. An implosive
device might be utilized as the seismic source. For example,
imploding spheres and other shapes have been used as underwater
acoustic sources for ocean applications as described in Heard, G.
J., McDonald, M., Chapman, N. R., Jashke, L., "Underwater light
bulb implosions--a useful acoustic source," Proc IEEE Oceans '97;
M. Orr and M. Schoenberg, "Acoustic signatures from deep water
implosions of spherical cavities," J. Acoustic Society Am., 59,
1155-1159, 1976; R. J. Urick, "Implosions as Sources of Underwater
Sound," J. Acoustic Society Am, 35, 2026-2027, 1963; and Giotto,
A., and Penrose, J. D., "Investigating the acoustic properties of
the underwater implosions of light globes and evacuated spheres,"
Australian Acoustical Society Conference, Nov 15-17, 2000. A device
with a vacuum or low pressure chamber which is released into the
water to sink will eventually implode when the hydrostatic pressure
exceeds the implosion threshold of the device. A triggering
mechanism may even be used to cause the device to implode before
pressure alone would do so as described in Harben, P. E., Boro, C.,
Dorman, Pulli, J., 2000, "Use of imploding spheres: an Alternative
to Explosives as Acoustic Sources at mid-Latitude SOFAR Channel
Depths," Lawrence Livermore National Laboratory Report,
UCRL-ID-139032. One example of an implosive device is commercial
light bulbs, as described in both Heard, G. J., McDonald, M.,
Chapman, N. R., Jashke, L., "Underwater light bulb implosions--a
useful acoustic source," Proc IEEE Oceans '97; and Giotto. The
controlled use of implosive sources in a wellbore is described in
U.S. Pat. No. 4,805,726 of Taylor, D. T., Brooks, J. E., titled
"Controlled Implosive Downhole Seismic Source."
SUMMARY OF THE INVENTION
[0007] In accordance with one embodiment of the invention, a method
is provided for estimating a value of a property of a fluid-filled
wellbore system. One step of the method is recording data including
at least one of pressure and rate of flow at one or more locations
in the wellbore system. The value of the property can then be
estimated by employing a model for predicting at least one of
pressure and rate of flow dependent upon parameters detailing at
least one of wellbore system geometry, viscoacoustic properties of
the fluid and entrained solids contained in the wellbore system,
locations of boundaries and entrained solids, and characteristics
and locations of disturbances to pressure and flow in the wellbore
system, in order to determine a best prediction of some attribute
of the recorded data. Implemented as an apparatus, this embodiment
includes at least one sensor operable to record the data at one or
more locations in the wellbore system; a model for predicting at
least one of pressure and rate of flow dependent upon parameters
detailing at least one of wellbore system geometry, viscoacoustic
properties of the fluid and entrained solids contained in the
wellbore system, locations of boundaries and entrained solids, and
characteristics and locations of disturbances to pressure and flow
in the wellbore system, in order to determine a best prediction of
some attribute of the recorded data; and an analyzer operable to
estimate the value of the property from the model.
[0008] In accordance with another embodiment of the invention, a
method is provided for detecting a predetermined condition in a
fluid-filled wellbore system. One step of the method is generating
at least one sound in the wellbore system in response to the
condition, such that a detectable change is created in some
characteristic of the emitted sound. Another step is detecting the
at least one sound and the change, the detection being indicative
that the predetermined condition has occurred. When implemented as
an apparatus the embodiment includes a trigger operable in response
to the condition; a generator operable to emit sound in the
borehole and to create a detectable change in some characteristic
of the emitted sound in response to the trigger; and at least one
sensor operable to monitor the sound and detect the change, the
detection being indicative that the predetermined condition has
occurred.
[0009] In accordance with another embodiment of the invention,
information can be communicated in real time across distances that
permit practical application of the invention. This is possible
because acoustic disturbances propagate more efficiently than
electromagnetic signals in a wellbore system. Further, because the
acoustic disturbances are wireless, the invention is less
susceptible to damage from the abrasiveness of the fracturing
slurry in comparison with exposed cables placed in the wellbore for
delivering data to the surface.
[0010] Further features and advantages of the invention will become
more readily apparent from the following detailed description when
taken in conjunction with the accompanying drawings.
BRIEF DESCRIPTION OF THE FIGURES
[0011] FIG. 1 is a schematic illustrating wireless downhole to
surface communication in a borehole system.
[0012] FIG. 2 is a graph illustrating transmitted pulses where
amplitude and frequency may be utilized to communicate information
in the borehole system.
[0013] FIG. 3 is a graph illustrating a tubewave associated with a
pulse of FIG. 2.
[0014] FIG. 4 is a schematic illustrating use of direct and
reflected tubewaves to calculate location of a device in the
borehole system.
[0015] FIG. 5 is a schematic illustrating use of acoustic
disturbances by a device in motion in the borehole system to
communicate a value of a property or occurrence of a condition.
[0016] FIG. 6 is a schematic illustrating use of reflected acoustic
disturbances to obtain information from an object in motion in the
borehole.
[0017] FIG. 7 is a schematic illustrating use of acoustic
disturbances to monitor movement of entrained cement both inside
and outside an annulus of the borehole system.
[0018] FIGS. 8 and 9 are a schematic and a graph illustrating use
of reflected acoustic disturbances to monitor setting of cement in
the borehole system.
[0019] FIGS. 10 and 11 are a schematic and a graph illustrating use
of a reflected acoustic disturbances to monitor conditions in the
borehole fluid.
DETAILED DESCRIPTION
[0020] FIG. 1 illustrates a borehole system which includes a
fluid-filled borehole (100) having a bottom (102) and a head (104).
The head is typically at the surface, and although the borehole is
illustrated as being perpendicular to the surface and linear from
head to bottom, the borehole may be at any angle and have changes
of direction.
[0021] A downhole device (106) is operable to communicate
wirelessly via acoustic disturbances (108) in the fluid. The
location of the downhole device (106) may be both fixed and known
if that is necessary for the communication to have practical use.
Alternatively, when location is not critical to the utility of the
communicated information, the downhole device may be either or both
mobile and at an unknown location.
[0022] A receiver unit located near the head of the borehole is
operable to receive and interpret the acoustic disturbances
generated by the downhole device. The receiver includes at least
one sensor (110) and a processor unit (112). The sensor may include
any number of individual sensors, e.g., an array of hydrophones.
The sensor is disposed in position to detect acoustic disturbances
generated within the borehole fluid. For example, the sensor could
be disposed near the head (104), as illustrated, or closer to the
bottom (102). Further, the sensor may be either fixed, e.g., to the
casing (114), or mobile, e.g., connected to coiled tubing. The
processor unit (112) includes a hydrophone digitizer (114), memory
(116) and analyzer (118), which are operative in response to
detected acoustic disturbances (108) to provide useful information
such as measurements of properties or an indication of a condition
within the borehole.
[0023] The acoustic disturbances (108) used to communicate
information via the borehole fluid can take any of various forms.
For example, the acoustic disturbances could include a continuous
wave, or one or more discreet pulses created by changing pressure
or flow of the fluid (since pressure and flow are interrelated in
the borehole system, changing one necessarily changes the other).
In terms of frequency, the acoustic disturbance will typically be
in the range from DC to 40 kHz, with perhaps the most useful
frequencies being in the range from 0.1 Hz to 2 kHz. The
pressure/flow change may be generated by an implosion, explosion,
piezoelectric force, interruption of a pump or valve, or other
means. As will be discussed in greater detail below, the acoustic
disturbances (108) may also be shaped or otherwise generated in a
manner that permits communication of more complex information, as
well as distinguishing different communications from one
another.
[0024] In perhaps the most basic embodiment, the acoustic
disturbance (108) is used to communicate the occurrence of a
condition. In particular, the acoustic disturbance is generated by
the downhole device (106) to communicate from a location of
interest to the receiver unit in response to some triggering
condition, i.e., to communicate that the condition has occurred.
Examples of triggering conditions include, but are not limited to,
a predetermined level of pressure, pH, temperature, background
radiation, location, velocity, state of cure of entrained cement,
period of time, and any combinations thereof. So, for example, an
acoustic pulse could be used to indicate that a cement slug had
cured sufficiently to permit a subsequent stage of completion
operations. In such an embodiment the receiver unit need only
distinguish the pulse from ambient noise, i.e., the pulse itself
does not contain any additional information other than that the
condition has occurred. Filters in the analyzer may be utilized to
facilitate distinguishing the acoustic disturbance from other
sources such as a pump used to move the fluid in the borehole.
[0025] Referring now to FIGS. 1 through 3, in a first alternative
embodiment the downhole device (106) generates an acoustic
disturbance (108) that is indicative of a value of a property. For
example, a series of pulses (200a, 200b, 200c), or at least one
shaped pulse, can be used to indicate a value measured or detected
by a sensor associated with the downhole device (106). Properties
for which values may be measured or detected include, but are not
limited to, pressure, pH, temperature, background radiation,
location, velocity, state of cure of entrained cement, period of
time, and any combinations thereof. Acoustic pulses may be shaped
in terms of amplitude and frequency in order to represent measured
or detected values, e.g., a temperature of 100 degrees C. For
example, the amplitude or frequency of the disturbance could be
proportional to the temperature measured by the downhole device.
Alternatively, a series of acoustic pulses might be used to
represent the values in a manner such as that typically utilized
for digital communications. Therefore, in an ideal system, any of
various measured or detected values can be communicated to the
surface with resolution defined at least in part by the range of
amplitude.
[0026] In practice, however, it will typically be desirable to have
the capability of processing the disturbance as measured by the
sensor (110), which will differ from the transmitted disturbance
(108) due to the effects of the wellbore system. FIG. 3 illustrates
a received disturbance (300) which is a tubewave resulting from a
single transmitted pressure pulse (200a, FIG. 2). The tubewave is
characterized by reflections of alternating polarity which decrease
in amplitude over time. In the case where a series of pulses are
being transmitted, whether or not amplitude and frequency convey
information, it is useful for the receiver unit (112) to process
the received disturbance to filter noise, distinguish the initial
pulse from reflections of earlier pulses, and otherwise account for
changes in the transmitted disturbance. More particularly, the
receiver unit is operable to account for various parameters of the
borehole system which can cause changes in the acoustic disturbance
between the downhole source and the receiver unit including but not
limited to wellbore system geometry, viscoacoustic properties of
the fluid and entrained solids contained in the wellbore system,
locations of boundaries and entrained solids, and characteristics
and locations of disturbances may alter the acoustic disturbance in
transit. The receiver unit may accomplish this by utilizing a model
of one or more of these parameters. The model, which may be stored
in the memory (116), is utilized to interpret the acoustic
disturbance as received by the sensor (110), in order to determine
a best prediction of some attribute of the recorded data, where the
attribute includes at least one of amplitude, frequency,
attenuation, dispersion and travel time. The model may yield useful
information such as the actual value of a property.
[0027] The model may include both general parameters and
borehole-specific parameters. For example, a generic model could
include parameters for a typical borehole system. Further, multiple
generic models might be provided for conditions typically found in
particular types of wells and particular stages of well development
and operation. Generic models could also be provided for particular
stimulation treatments. Further, borehole specific models could be
generated, either independently or by modifying a generic model, in
order to adapt the sensor unit to the conditions of the borehole
under observation.
[0028] Some specific applications of the illustrated embodiment
include, but are not limited to, disturbance generation sources on
screens, packers, and casing collars. For example, a disturbance
source could be secured to a casing float collar to indicate
hydrostatic pressure measurement during cement set. Another
specific application is sources run while logging during completion
of well. For example, a source could be set while logging to
trigger when a perf gun reaches a desired location.
[0029] FIG. 4 illustrates use of a mobile downhole device (400) at
an unknown location, where location is calculated from comparison
of direct and reflected acoustic disturbances. The mobile downhole
device (400) is introduced into the fluid being pumped into the
borehole via an inlet (402) between the pump (404) and the head
(104). The downhole device (400) is designed to generate an
acoustic disturbance when a particular condition is encountered,
e.g., by imploding when the pressure exceeds a predetermined
implosion value. Once introduced into the fluid, the downhole
device is carried down the borehole by at least one of (a) the
fluid being pumped and (b) the force of gravity. In the case of a
pressure-sensitive device (400), when the pressure to which the
downhole device is subjected exceeds the implosion value, the
acoustic disturbance is generated. The acoustic disturbance
generates strong tubewaves (108a, 108b-1) which travel both up and
down the borehole, i.e., an up-going tubewave (108a) and a
down-going tube wave (108b-1). The up-going tubewave (108a)
propagates upward through the borehole to the head (104). The
down-going tubewave (108b-1) propagates downward and is strongly
reflected by the bottom of the borehole (102). The reflected,
down-going tubewave (108b-2) then propagates upward to the head.
The direct up-going and reflected down-going tubewaves are both
detected by the sensor (110) at or near the borehole head. A clock
circuit of the processor unit is employed to measure the difference
in time between detection of the tubewaves (108a, 108b-2). The
depth at which the acoustic disturbance occurred is then calculated
by the processor unit (112) from the time-lag between the direct
up-going tubewave (108a) and the reflected down-going tubewave
(108b-2), yielding a depth D-Z (measured along the length of the
borehole from the bottom of the well (102)) at which the pressure
exceeds the implosion value. Since the implosion value of pressure
for the downhole device is known, the result is a data point
indicative of actual pressure at the depth Z.
[0030] It should be noted that the down-going tubewave (108b-1) may
be reflected before reaching the bottom of the borehole (102). For
example, a major change in borehole impedance may cause reflection
of the down-going tubewave. In some cases it may be necessary to
distinguish that reflection from a reflection at the bottom of the
borehole. In other cases where the depth of the feature is known,
the tubewave reflected by the feature may be employed in the depth
calculation. Other signals generated by the acoustic disturbance
such as extensional or flexural waves in the casing might also be
detected at the surface. If they are present and have known
propagation speed then they may be used as an additional or
alternative method for determining the depth of the acoustic
disturbance. Still other noise, such as that generated by the pump
(404), may need to be removed by filtering.
[0031] Other signals generated by the implosion such as extensional
or flexural waves in the casing might also be detected at the
surface. If they are present and have known propagation speed then
they may be used as an additional or alternative method for
determining the depth of the implosion. Still other signals, such
as those generated by a pump, may need to be removed by
filtering.
[0032] Various techniques may be employed to calculate acoustic
disturbance depth from the delta of tubewave arrival times. For
example, the propagation speed, V, of the tubewave in a
fluid-filled cased borehole is described by White (1983) as:
V=[.rho.(1/B+1/(.mu.+(Eh/2b))].sup.-1/2
where .rho. is fluid density, B is the bulk modulus of the fluid,
.mu. is the shear modulus of the rock, E is Young's modulus for the
casing material, h is the casing thickness and b is the casing
outer diameter. For a water-filled borehole, an acceptable
approximation of V is 1450 m/s. For drilling mud this velocity may
vary slightly due to increases in the density, .rho., or changes in
the bulk modulus, B. Either density or bulk modulus can be measured
for a particular fluid under consideration, and modifications made
to the value of V if necessary.
[0033] Various techniques may be employed for calibrating the
tubewave speed. For example, multiples show the total roundtrip
period. Further, autocorrelation of pump noise shows the total
roundtrip period. Still further, a source at the surface can
determine total roundtrip period.
[0034] In the embodiment illustrated in FIG. 3, acoustic
disturbance depth is calculated for a borehole of known total
depth, D, and an acoustic disturbance at an unknown depth, Z,
occurring at unknown time, T.sub.0. The up-going tubewave (108a) is
detected at the sensor (110) at the top of the borehole at time
T.sub.1. Since the time of the acoustic disturbance T.sub.0 and the
depth, Z, are unknown, the result cannot be calculated from T.sub.1
alone. However, if the arrival time of the tubewave (108b-2)
reflected from the bottom of the borehole, T.sub.2, is recorded
then two equations for two unknowns are available:
T.sub.1-T.sub.0=Z/V
and
T.sub.2T.sub.0=(2D-Z)/V.
The unknown origin time can then be eliminated from these two
equations to obtain an expression for the depth of the acoustic
disturbance:
Z=D-V(T.sub.2-T.sub.1)/2.
[0035] There are a variety of techniques to detect tubewave arrival
times and arrival delays, including manual picking, automatic
thresholding algorithms, and autocorrelation based approaches. More
sophisticated approaches may be required if the typical noise field
is more complex, or if multiple canisters designed to implode at
varying pressures are deployed simultaneously. As already described
above, modeling may be employed to interpret the acoustic
disturbance as received by the sensor, i.e., in order to determine
a best prediction of some attribute of the recorded data, where the
attribute includes at least one of amplitude, frequency,
attenuation, dispersion and travel time.
[0036] FIG. 5 illustrates use of acoustic disturbances (108) by a
device (500) in motion in the borehole. Unlike the previously
described embodiment, only a direct tubewave is employed to
communicate information. The device (500) can be configured to
utilize acoustic disturbances to communicate occurrence of a
condition and values of properties to the surface in the manner
already described above. Further, the device could communicate
location by, for example, generating an acoustic disturbance at
each collar (502). The receiver unit (112) could then calculate
position by multiplying the number of collar transits by the
distance between collars. Specific applications include, but are
not limited to, cement wiper plugs that pulse or siren, pulsing
BHA's, a pulse emitter on coiled tubing, analogues to wiper plugs
for fracturing and acidizing, noisy spacer fluids to detect
progress of fluids in the borehole, and a repeater pulse with an
accurate clock.
[0037] Because the downhole device (500) is in motion, the receiver
unit may obtain information about the location and velocity of the
downhole device from the Doppler effect on the acoustic
disturbances. In particular, a frequency shift is induced in the
acoustic disturbance (108) as a function of velocity and direction
relative to the sensor. Since the borehole system may also have an
effect on the acoustic disturbances, modeling may be utilized, as
already described above, to facilitate interpretation of the
received acoustic disturbances.
[0038] FIG. 6 illustrates locating downhole objects with time lapse
response and interferometry. In a simple scenario where the object
(600) is stationary, an acoustic disturbance (108c-1) is initiated
by a source (602) at a remote location at a known time, as measured
by a clock circuit. The remote location is depicted as being
proximate to the borehole head, but any location apart from the
downhole object would be considered a remote location. The acoustic
disturbance (108c-1) propagates through the borehole and is
reflected by the downhole object (600). The reflected disturbance
(108c-2) is then detected by the sensor (110) associated with the
processor unit at a known time as measured by the clock circuit.
The location of the downhole object can then be calculated from the
round trip propagation time of the acoustic disturbance, i.e.,
108c-1 and 108c-2. Since propagation time can be effected by the
borehole environment, the modeling technique already described may
be utilized to facilitate interpretation of the received
disturbance. Some specific applications of this embodiment include,
but are not limited to, locating cement wiper plugs, locating
cement slugs, sand plugs, and packers, locating perforations and
fractures, locating obstructions in pipelines, locating gas
bubbles, monitoring frac extension, monitoring an acid bailout,
evaluating filter cake integrity, and optimizing coiled tubing (CT)
cleanout.
[0039] The downhole object may include a reflector configured to
modulate the disturbance in order to communicate information to the
sensor unit. For example, the frequency and amplitude of the
disturbance could be modulated in order to communicate the value of
a property. Modeling may be required in order to distinguish the
effects of modulation of the disturbance by the downhole device
from effects induced by the borehole system.
[0040] In the case where the object is in motion, the receiver unit
may obtain information about the location and velocity of the
downhole device from the Doppler effect on the acoustic
disturbances. In particular, a frequency shift is induced in the
acoustic disturbance as a function of velocity and direction
relative to the sensor. Since the borehole system may also have an
effect on the acoustic disturbances, modeling may be utilized, as
already described above, to facilitate interpretation of the
received acoustic disturbances.
[0041] FIG. 7 illustrates monitoring progress of an entrained
material (700) such as cement. The entrained material is introduced
into the borehole inside an annulus (702) such as a metal casing.
At some location, such as the bottom of the borehole, the entrained
material moves to the outside of the annulus, and changes
direction, i.e., moves back toward the surface. When positioning
cement outside the annulus during well completion, it is useful to
know the location of both the leading and trailing edges (704, 706)
of the entrained cement. It should be noted that the distance
between the leading and trailing edges is variable because the
cross-sectional area outside the annulus can vary significantly
because of fractures. In order to monitor the progress of both
edges, acoustic disturbances (108d-1, 108e-1) are introduced both
inside and outside the annulus. The edges (704, 706) will reflect
at least a portion of the acoustic disturbances such that location
can be determined from round trip time and modeling of reflected
acoustic disturbances (108d-2, 108e-2) as already described above.
The disturbances may be generated by operating a valve (708)
connecting the fluid inside the annulus with the fluid outside the
annulus, or alternatively by separate acoustic sources (702a,
702b). With the valve in a closed position it will be expected that
there should be a pressure differential across the annulus. Hence,
by opening the valve it is possible to generate acoustic
disturbances on either side of the annulus which will be equal in
amplitude and opposite in polarity. The reflected acoustic
disturbances are detected by separate sensors (110a, 110b)
[0042] FIGS. 8 and 9 illustrate an embodiment for monitoring an
object (800) based on changing reflection. An acoustic disturbance
(108f-1) is initiated at a remote location. The remote location is
depicted as being proximate to the borehole head, but any location
apart from the downhole object would be considered a remote
location. The acoustic disturbance (108f-1) propagates through the
borehole and is reflected by the downhole object (800). The
reflected disturbance (108f-2) is then detected by the sensor
associated with the receiver unit at a known time as measured by
the clock circuit. The state of the object (800) may be calculated
from the strength of the reflection, e.g., the reflection
coefficient, as interpreted by a model of effects of the borehole
system on the acoustic disturbance. Alternatively, multiple
reflected disturbances can be detected over time in order to obtain
information from the magnitude and rate of change in reflection
coefficient over time. Some specific applications of this
embodiment include, but are not limited to, monitoring cement slugs
as they set, monitoring packers as they inflate or swell,
monitoring gravel pack placement, and CT cleanout. In the case of a
setting cement slug, for example, it would be expected that the
amplitude of reflected disturbances (108f-2) would increase in
proportion to the level of cure of the cement as illustrated in
FIG. 9.
[0043] FIGS. 10 and 11 illustrate an embodiment for monitoring
conditions in the fluid (1000) traversed in the borehole system. As
in the previous embodiment, an acoustic disturbance (108g-1) is
introduced at a remote location by an acoustic source (602), and
the reflected disturbance (108g-2) is detected by the sensor (110).
However, it is not the changing reflection coefficient of the
reflector (1002) that is monitored, but rather the effect of the
intervening fluid (1000) on the disturbances. Therefore, it is
preferable that the reflector (1002) remain relatively constant
during the time period in which measurements are taken. The
borehole fluid can effect the disturbance in terms of attenuation,
dispersion and travel time. A model is employed for predicting
response dependent upon parameters detailing at least one of
wellbore system geometry, viscoacoustic properties of the fluid and
entrained solids contained in the wellbore system, locations of
boundaries and entrained solids, and characteristics and locations
of disturbances to pressure and flow in the wellbore system, in
order to determine a best prediction of some attribute of the
detected disturbances. Potential applications for this embodiment
include, but are not limited too, monitoring cement setting by
pulsing fluid inside casing, simultaneously monitoring both sides
of an annulus, monitoring fluid properties including viscosity,
density, and temperature, detection of solids suspended in fluid,
including CT cleanout, detection of scale, unsuspended solids,
filter cakes, and the like, and CT cleanout.
[0044] While the invention is described through the above exemplary
embodiments, it will be understood by those of ordinary skill in
the art that modification to and variation of the illustrated
embodiments may be made without departing from the inventive
concepts herein disclosed. Moreover, while the preferred
embodiments are described in connection with various illustrative
structures, one skilled in the art will recognize that the system
may be embodied using a variety of specific structures.
Accordingly, the invention should not be viewed as limited except
by the scope and spirit of the appended claims.
* * * * *